1. Field of the Disclosure
The present disclosure generally relates to apparatus and methods for managed pressure drilling. More particularly, the present disclosure relates to apparatus and methods to drill subsea wellbores offshore through drilling risers in managed pressure drilling operations. More particularly still the present disclosure relates to apparatus and methods including rotating control devices having packing elements retrievable through upper portions of drilling risers.
2. Background Art
Wellbores are drilled deep into the earth's crust to recover oil and gas deposits trapped in the formations below. Typically, these wellbores are drilled by an apparatus that rotates a drill bit at the end of a long string of threaded pipes known as a drillstring. Because of the energy and friction involved in drilling a wellbore in the earth's formation, drilling fluids, commonly referred to as drilling mud, are used to lubricate and cool the drill bit as it cuts the rock formations below. Furthermore, in addition to cooling and lubricating the drill bit, drilling mud also performs the secondary and tertiary functions of removing the drill cuttings from the bottom of the wellbore and applying a hydrostatic column of pressure to the drilled wellbore.
Typically, drilling mud is delivered to the drill bit from the surface under high pressures through a central bore of the drillstring. From there, nozzles on the drill bit direct the pressurized mud to the cutters on the drill bit where the pressurized mud cleans and cools the bit. As the fluid is delivered downhole through the central bore of the drillstring, the fluid returns to the surface in an annulus formed between the outside of the drillstring and the inner profile of the drilled wellbore. Because the ratio of the cross-sectional area of the drillstring bore to the annular area is relatively low, drilling mud returning to the surface through the annulus do so at lower pressures and velocities than they are delivered. Nonetheless, a hydrostatic column of drilling mud typically extends from the bottom of the hole up to a bell nipple of a diverter assembly on the drilling rig. Annular fluids exit the bell nipple where solids are removed, the mud is processed, and then prepared to be re-delivered to the subterranean wellbore through the drillstring.
As wellbores are drilled several thousand feet below the surface, the hydrostatic column of drilling mud serves to help prevent blowout of the wellbore as well. Often, hydrocarbons and other fluids trapped in subterranean formations exist under significant pressures. Absent any flow control schemes, fluids from such ruptured formations may blow out of the wellbore like a geyser and spew hydrocarbons and other undesirable fluids (e.g., H2S gas) into the atmosphere. As such, several thousand feet of hydraulic “head” from the column of drilling mud helps prevent the wellbore from blowing out under normal conditions.
However, under certain circumstances, the drill bit will encounter pockets of pressurized formations and will cause the wellbore to “kick” or experience a rapid increase in pressure. Because formation kicks are unpredictable and would otherwise result in disaster, flow control devices known as blowout preventers (“BOPs”), are mandatory on most wells drilled today. One type of BOP is an annular blowout preventer. Annular BOPs are configured to seal the annular space between the drillstring and the inside of the wellbore. Annular BOPs typically include a large flexible rubber packing unit of a substantially toroidal shape that is configured to seal around a variety of drillstring sizes when activated by a piston. Furthermore, when no drillstring is present, annular BOPs may even be capable of sealing an open bore. While annular BOPs are configured to allow a drillstring to be removed (i.e., tripped out) or inserted (i.e., tripped in) therethrough while actuated, they are not configured to be actuated during drilling operations (i.e., while the drillstring is rotating). Because of their configuration, rotating the drillstring through an activated annular blowout preventer would rapidly wear out the packing element.
As such, rotary drilling heads are frequently used in oilfield drilling operations where elevated annular pressures are present. A typical rotary drilling head includes a packing element and a bearing package, whereby the bearing package allows the packing element to rotate along with the drillstring. Therefore, in using a rotary drilling head, there is no relative rotational movement between the packing element and the drillstring, only the bearing package exhibits relative rotational movement. Examples of rotary drilling heads include U.S. Pat. No. 5,022,472 issued to Bailey et al. on Jun. 11, 1991 and U.S. Pat. No. 6,354,385 issued to Ford et al. on Mar. 12, 2002, both assigned to the assignee of the present application, and both hereby incorporated by reference herein in their entirety.
When the pressure of the hydrostatic column of drilling mud is less than the formation pressure, the drilling operation is said to be experiencing an “underbalanced” condition. While running an underbalanced drilling operation, there is increased risk that the excess formation pressure may cause a blowout in the well. Similarly, when the pressure of the hydrostatic column exceeds the formation pressure, the drilling operation is said to be experiencing an “overbalanced” condition. While running an overbalanced drilling operation, there is increased risk that the drilling fluids may invade the formation, resulting in loss of annular return pressure, and the loss of expensive drilling fluids to the formation. Therefore, under most circumstances, drilling operations are desired to be either balanced operations or slightly underbalanced or overbalanced operations.
In certain drilling circumstances, the pressures contained within the drilled formation are elevated. One mechanism to counter such elevated pressures is to use a higher specific gravity drilling mud. By using such a “heavier” mud, the same height column may be able to resist and “balance” a higher formation pressure. However, there are drawbacks to using a heavy drilling mud. For one, heavier mud is more difficult to pump down through the drill bit at high pressures, and may result in premature wear of pumping and flow control equipment. Further, heavier mud may be more abrasive on drilling fluid nozzles and other flowpath components, resulting in premature wear to drill bits, mud motors, and MWD telemetry components. Furthermore, heavier mud may also not be as effective at cooling and removing cuttings away from drill bit cutting surfaces.
One alternative to drilling in formations having elevated pressure formations is known as managed pressure drilling (“MPD”). In managed pressure drilling, the annulus of the wellbore is capped and the release of returning drilling mud is regulated such that increased annular pressures may result. In an MPD operation, it is not uncommon to increase the annular return pressure, and thus the hydrostatic head opposing the formation pressure, by 500 psi or more to achieve the balanced, underbalanced, or overbalanced drilling condition desired. By using a rotary drilling head having a regulated annular output, formation pressures may be more effectively isolated to maximize drilling rate of penetration.
While MPD operations are relatively simple operations to perform on land, they become considerably more difficult and complex when dealing with offshore drilling operations. Typically, an offshore drilling operation undertakes to drill a wellbore from a subsea wellhead installed on a sea floor. Typically, depending on the depth of water in which the operations are to be carried out, a long string of connected pipe sections known as a riser extends from the subsea wellhead to the drilling rig at the surface. Under normal operations, a drillstring may extend from the drilling rig, through the riser and to the wellbore through the subsea wellhead as if the riser sections are a mere extension of the wellbore itself. However, in various subsea locations, particularly in very deep water, formation pressures of undersea hydrocarbon deposits may be extraordinarily high. As such, to avoid extreme underbalanced conditions while drilling in deep water, MPD operations are increasingly becoming important for offshore drilling rigs.
Drawbacks to performing operations with former offshore rigs include the elevated pressures associated with MPD operations. Particularly, various components (e.g., slip joints, diverter assemblies, etc.) of the upper portion of riser assemblies are not designed to survive the elevated pressures of MPD operations. One solution produced by Williams Tool Company, Inc. is known as the RiserCap™ rotating control head system. In this system, the upper portion of the riser assembly is removed and a rotary drilling head-type apparatus is installed. Once installed, MPD operations may proceed with the exposed drillstring engaging the top of the RiserCap™ assembly (located below the rig floor) and extending into the lower riser assembly. The rotating head assembly of the RiserCap™ isolates the high-pressure annular fluids from the atmosphere and diverts them through a discharge manifold. When MPD operations are to cease, an annular BOP is engaged, the RiserCap™ assembly is removed, and the upper portion of the former riser assembly is replaced.
One issue with the RiserCap™ system marketed by Williams Tool Company, Inc. is that a significant amount of time and labor is required each time an MPD operation is called for. Because the upper portion of the drilling riser including the diverter assembly and slip joint is often removed, the RiserCap™ system is not practical for non-MPD operations. As such, hours of rig time to set-up and subsequently dismantle the RiserCap™ system must be budgeted for each MPD operation. Furthermore, significant rig storage space, always at a premium on offshore rigs, must be devoted to storing the RiserCap™ system and all the tooling and support components associated therewith.
As such, embodiments of the present disclosure are directed to a riser assembly and method of use that enables both MPD and non-MPD operations to be performed with a single riser assembly. Particularly, the riser assembly disclosed allows for rapid switching between MPD and non-MPD operations without requiring complicated make-up and take-down operations to be performed on the riser. Furthermore, embodiments disclosed herein allow a pre-existing riser assembly to quickly and easily be converted to dual purpose MPD/non-MPD operation.